1. Field of the Invention
The present invention relates to the analysis of downhole hydrocarbon fluids. More particularly, the present invention relates to apparatus and methods for the in situ determination of the density of hydrocarbon fluids in a geological formation.
2. State of the Art
Naturally occurring hydrocarbon fluids include a wide range of fluids including dry natural gas, wet gas, condensate, light oil, black oil, heavy oil, and heavy viscous tar. The physical properties of these various hydrocarbon fluids, such as density, viscosity, and compressibility vary considerably. In addition, the separation of each of the hydrocarbon fluid compositions into distinctly separate gas, liquid and solid phases, each with its own physical properties, occurs at certain contours of pressure and temperature within the formation. This is referred to generally as the xe2x80x9cphase behaviorxe2x80x9d of the hydrocarbon.
The economic value of a hydrocarbon reserve, the method of production, the efficiency of recovery, the design of production hardware systems, etc., all depend upon the physical properties and phase behavior of the reservoir hydrocarbon fluid. Hence, it is important that the fluid properties and phase behavior of the hydrocarbon be determined accurately following the discovery of the hydrocarbon reservoir, so that a decision of whether it is economically viable to develop the reservoir can be made; and if viable, an appropriate design and plan for the development of the reservoir can be adopted. With that in mind, those skilled in the art will appreciate that the ability to conduct an analysis of formation fluids downhole (in situ) is extremely desirable.
The assignee of this application has provided a commercially successful borehole tool, the MDT (a trademark of Schlumberger) which analyzes formation fluids in situ. The MDT extracts and analyzes a flow stream of fluid from a formation in a manner substantially as set forth in co-owned U.S. Pat. Nos. 3,859,851 and 3,780,575 to Urbanosky which are hereby incorporated by reference herein in their entireties. The OFA (a trademark of Schlumberger), which is a module of the MDT, determines the identity of the fluids in the MDT flow stream and quantifies the oil and water based on other co-owned technology. In particular, co-owned U.S. Pat. No. 4,994,671 to Safinya et al. provides a borehole apparatus which includes a testing chamber, means for directing a sample of fluid into the chamber, a light source preferably emitting near infrared rays and visible light, a spectral detector, a data base means, and a processing means. Fluids drawn from the formation into the testing chamber are analyzed by directing the light at the fluids, detecting the spectrum of the transmitted and/or backscattered light, and processing the information accordingly in order to quantify the amount of water and oil in the fluid. As set forth in co-owned U.S. Pat. No. 5,266,800 to Mullins, by monitoring the optical absorption spectrum of the fluid samples obtained over time, a determination can be made as to when a formation oil is being obtained as opposed to a mud filtrate. Thus, the formation oil can be properly analyzed and quantified by type.
The Safinya et al., and Mullins patents represent great advances in downhole fluid analysis, and are particularly useful in the analysis of oils and water present in the formation. The issues of in situ gas quantification and analysis are addressed in the co-owned U.S. Pat. No. 5,167,149 to Mullins et al., U.S. Pat. No. 5,201,220 to Mullins et al., U.S. Pat. No. 5,859,430 to Mullins et al., U.S. Pat. No. 5,939,717 to Mullins, and in O. C. Mullins et al., xe2x80x9cEffects of high pressure on the optical detection of gas by index-of-refraction methodsxe2x80x9d, Applied Optics, Vol. 33, No. 34, pp. 7963-7970 (Dec. 1, 1994). In particular, U.S. Pat. No. 5,859,430 to Mullins et al. discloses a method and apparatus for the downhole compositional analysis of formation gases which utilizes a flow diverter and spectrographic analysis. More particularly, the apparatus includes diverter means for diverting formation gas into a separate stream, and a separate gas analysis module for analyzing the formation gas in that stream. The methods and apparatus are useful in determining what types of gas are present in the formation fluid. U.S. Pat. No. 5,939,717 to Mullins, on the other hand, is directed to methods and apparatus for determining in situ gas-oil ratios (GOR) which are necessary for establishing the size and type of production facilities required for processing newly discovered oil.
Despite these large advances in downhole analysis and quantification of oil, gas, and water, and gas-oil ratios, additional information regarding physical properties of the hydrocarbons such as the hydrocarbon compressibility and density are desired. Previously incorporated Ser. No. 09/704,630 discloses methods and apparatus for optically measuring fluid compressibility downhole. The compressibility of a formation hydrocarbon sample is determined downhole by using a borehole tool to obtain the sample downhole, and, at two different pressures, subjecting the sample to near infrared illumination and conducting spectral absorption measurement of peaks at and/or around about 6,000 cmxe2x88x921 and/or at and/or about 5,800 cmxe2x88x921 (the absorption peaks of methane and crude oil respectively). The compressibility of the sample is determined from the change in the peak areas, the change in pressure, and the measured peak area itself. According to a preferred embodiment of the invention, the pressure is changed at least 2000 pounds per square inch (psi), and preferably 4000 or more psi between measurements.
Fluid density measurement normally requires the measurement of the volume occupied by a known mass or the measurement of the mass of a known volume. Density can be determined in a laboratory by analyzing a fluid sample taken downhole from the formation. These measurements are time consuming and suffer from systematic errors that arise from irreversible changes in the sample upon transportation from downhole to the laboratory. These measurements also assume that a representative sample was obtained by the sampling tool. Although these measurements could be performed at the well head, thereby reducing the time required for an identification of low quality samples, such measurements would still be subject to the issues of sample changes that might occur while the sample is brought from downhole to the surface.
It is therefore an object of the invention to provide methods and apparatus for measuring fluid density downhole.
It is also an object of the invention to provide methods and apparatus for measuring fluid density downhole with a sampling device during investigative logging.
It is another object of the invention to provide methods and apparatus for measuring fluid density downhole with permanent sensors during production logging.
It is still another object of the invention to provide methods and apparatus for measuring fluid density downhole of both stagnant fluid and flowing fluid.
In accord with these objects which will be discussed in detail below, the methods of the present invention include measuring the compressibility of fluid using the methods and Optical Fluid Analyzer apparatus of the previously incorporated co-owned application, measuring the speed of sound in the downhole fluid, and calculating fluid density based on the compressibility of the fluid and the speed of sound through the fluid. The apparatus of the invention includes at least one sound transceiver and a signal processor. Prior to or after the compressibility of the fluid is obtained, sound is transmitted through the fluid and reflected back to the sound transceiver over a known distance. The signal processor calculates the time delay between the transmission and reception, and, using the known distance, calculates the speed of sound through the fluid. The speed of sound is then used with the compressibility of the fluid to determine density based on a known physical relationship between isentropic compressibility, speed of sound and density.
The sound transceiver is preferably mounted within the tubing of the Optical Fluid Analyzer so that compressibility and speed of sound measurements can be made on the same sample.
According to another embodiment of the apparatus of the invention, two sound transceivers are used so that the speed of sound can be measured in two opposite directions through the fluid. This allows the measurement of the flow rate of flowing fluid as well as the speed of sound through the fluid. Off the shelf ultrasonic xe2x80x9ctime of flightxe2x80x9d flow meters may be adapted to suit the methods of the invention. These devices typically utilize quartz transducers and generate sound pulses in the range of ten micro seconds to one millisecond with a frequency in the range of 100 KHz to one MHz.
Alternate embodiments of the invention contemplate permanent or semi-permanent installations of sensors so that the density of the formation fluids may be measured during production.
Additional objects and advantages of the invention will become apparent to those skilled in the art upon reference to the detailed description taken in conjunction with the provided figures.